IR 05000289/1985021

Safety Insp Rept 50-289/85-21 on 850802-0916.Violations Noted:Failure to Conduct Complete Search of Escorted Individual.Portions Deleted (Ref 10CFR2.790(a))

ML20138F134
Person / Time
Site:	Three Mile Island
Issue date:	10/14/1985
From:	Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20138F098	List: IR 05000289/1985021 IR 05000802/2009016 ML20138F094
References
50-289-85-21, NUDOCS 8510250193
Download: ML20138F134 (33)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-21 Docket N License N DPR-50 Priority -- Category C Licensee: GPU Nuclear Corporation Post Office Box 480 Middletown, Pennsylvania 17057 Facility Name: Three Mile Island Nuclear Station, Unit 1 Inspection At: Middletown, Pennsylvania Inspection Conducted: August 2 - September 16, 1985 Inspectors: N. Blumberg, Lead Reactor Engineer, Region I J. Bryant, Senior Resident Inspector (0conee),

Region II D. Haverka.np, Technical Assistant for TMI-1 Restart; Region I D. Trimble, Resident Inspector (Calvert Cliffs), Region I R. Urban, Reactor Engineer, Region I P. Wen, Reactor Engineer, Region I F. Young, Resident Inspector (TMI-1), Region I Contractor Personnel: B. Gore, Research Scientist, Battelle PNL Approved by: /chY/fy-R. Conte, TMI-1 Restart Manager Date THI-1 Restart Staff Division of Reactor Projects Inspection Summary:

Routine and special (NRC shift coverage) safety inspection (348 hours0.00403 days <br />0.0967 hours <br />5.753968e-4 weeks <br />1.32414e-4 months <br />)

of hot shutdown activities in preparation for TMI-1 restart; operator response to significant events and licensee event handling including followup of corrective actions; security plan implementation; equipment operability; surveillance testing in preparation for restart; refueling cavity water seal design; licensee investigation of alleged internal improprieties; selected TMI task action plan items; licensee response and followup action on a licensee event report; strike plans; and overall restart readiness of the facility and licensee managemen PDR ADOCK 05000289 G PDR

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Iispection Results:

Licensee upper management and various oversight groups continued their detailed involvement in site activities. Personnel properly implemented facility procedures for the hot shutdown evolutions and surveillance testing. Operators were responsive to the significant events that occurred during this period in that they properly used emergency procedures and their basic knowledge to assess unique circumstances and take appropriate corrective actio The licensee training program was a factor in contributing to the correct response of operators to various events. In response to these events and other less significant events, licensee representatives properly implemented their event documentation administrative controls and they provided an appropriate level of review to determine adequate corrective actions. Most notable of these was the troubleshooting effort on the fire in the rod control system. However, with respect to a less significant emergency feedwater flow instrument problem, there was a communication problem with the NRC staff because troubleshooting efforts were not complete, due in part to the need for licensee resources to support the then potential restart on August 29, 198 Certain instruments important to safety are subject to a single failure on loss of the non-nuclear instrumentation, however, these instruments are backed-up by local indications or other indications that in some instances are not safety grade instrumentation. Selected TMI task action plan modifications were verified to be complet Licensee action in response to previous events or regulatory issues was satisfactory and corrective actions taken were appropriate. One violation (failure to conduct a complete search of an escorted individual) was identified, and corrective actions were completed satisfactorily during this inspection perio .

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DETAILS Introduction s During the inspection period, the licensee maintained the plant in a hot shutdown condition (reactor coolant system near 530 F and 2155 psig) to maintain restart readiness and to continue operator training pending further action by the U.S. Court of Appeals for the Third Circuit in Philadelphia, Pennsylvania. On August 27, 1985, the three member panel of judges from that court issued a judgenent that denied the petition for review of the Commission's Order (CLI-85-09) permitting restart. However, on August 29, 1985, the panel ordered that the existing stay remain in effect until petitioners could file appeals to the full court. On August 28, 1985, in anticipation of restart, Region I resumed shift inspector coverage. This lasted only 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> as a result of the decision that the stay of the Commission's Order was to remain in effec Throughout the balance of the inspection period, the TMI-1 Restart Staff provided routine inspection coverag . Shift Inspection Activities 2.1 ~ Review On August 28-29, 1985, Region I resumed its augmented inspection coverage. The NRC shift inspectors assessed the adequacy and effectiveness of operating personnel performance, based on the inspectors' observations of preoperational activities to determine that:

-- operators are attentive and responsive to plant parameters and conditions;

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plant evolutions and testing are planned and properly

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procedures are used and followed as required by plant policy;

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equipment status changes are appropriately documented and communicated to appropriate shift personnel;

-- the operating conditions of plant equipment are effectively monitored, and appropriate corrective action

.is initiated when required;

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backup instrumentation, measurements, and readings are used as appropriate when normal instrumentation is found to be defective or out of tolerance;

-- logkeeping is timely, accurate, and adequately reflects plant activities and status; i

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operators follow good operating practices in conducting plant operations; and,

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operator actions are a result of performance-oriented trainin The region-based inspectors also assisted the in the overall restart readiness review (described in paragraph 12) by conducting selected important to sEfety systems valve lineup verification .2 Findings, The inspectors did not identify any condition adverse to nuclear safety' or inconsistent with regulatory requirement Cperators continued to perform their duties in a professional renner and were attentive to the various alarms received in the control room. Procedures were in use and continued to be properly implemented. The shift turnover and briefing for the shift that was to take the reactor critical was particularly noteworthy. Plant status and the methodology for the criticality evolution were discussed in detail. The discussion not only reflected an orientation toward nuclear safety, but it also reflected an earnest desire to do a quality job. The inspectors had no additional comments as a result of this revie . Plant Operations During Hot Shutdown 3.1 Routine Review

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The resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operating requirements of Section 6 of the Technical Specifications (TS)

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-- review of selected plant parameters for abnormal trends;

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plant status from a maintenance / modification viewpoint including plant housekeeping and fire protection measures;

-- control of ongoing and special evolutions, including control room personnel awareness of these evolutions;

-- control of documents including log-keeping practices;

-- implementation of radiological controls; and,

-- implementation of the security plan including access control, boundary integrity ard badging practices.

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The inspectors focused on the following areas:

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control room operations during regular and backshift hours including frequent observation of activities in progress and periodic reviews of selected sections of the shift foreman's log and control room operator's log and selected sections of other control room daily logs;

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areas outside the control room; and,

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selected licensee planning meeting As a result of this review, the inspectors reviewed specific events in more detail as noted belo .2 Event Review and Reporting Requirements The inspector reviewed licensee administrative procedures and related records for handling significant events and NRC reporting requirements to assure that:

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requirements stated in procedures are consistent with NRC reporting requirements for 10 CFR 20, 50, and 73;

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requirements exist to provide plant personnel with lessons learned information; and,

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related administrative procadures are properly implemente Selected sections of the following procedures were reviewed:

Administrative Procedure (AP) 1012, Revision 26, September 11, 1984, " Shift Relief and Log Entries," and AP 1044, Revision 14, June 4, 1985, " Event Review and Reporting Requirements."

The inspector also reviewed selected entries in the shift foreman log covering event reporting and the Plant Review -

Group Chairman's file of AP 1044, Enclosure 7, "Potentially Reportable Event Forms." During previous inspections, the inspector had reviewed selected plant incident reports prepared in accordance with AP 1029, Revision 17, July 29, 1985, " Conduct of Operations," along with selected event-related entries in the shift foreman's narrative 109 Based on this sampling review, the inspector found no inconsistencies between AP 1044 reporting requirements and applicable Code of Federal Regulations reporting requirement Further, the licensee's procedures reflect an initiative to classify and report lower threshold events such as " Events of Potential Public Interest," or "Public Inquiry Reports." This level of reporting enhances licensee management awareness to anticipate the escalation in significance of selected event The reports are also made to the NRC's resident office for informatio ,

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. The reporting system is complemented by the AP 1012 requirement for the shift foreman to log 'significant events including the entries into Technical Specification action statements. This 109 is reviewed by Operations Department management who are familiar generally with the recorded events and underlying causes for those events. At the discretion of plant management, plant incident reports are prepared which provide useful feedback to plant personnel on lessons learned from the more significant events that occur in the plan The inspector also verified proper implementation of the applicable sections of the referenced AP In 1984 approximately 50 Potentially Reportable Event Forms were completed. Of these events, 23 events resulted in 7 Licensee Event Reports (event forms were either duplicated or were multiple examples of a common problems, such as fire barrier degradation). Of the events reviewed, the inspector identified no instances in which the licensee failed to make a required report or complete a required LE .3 Security Plan Implementation On May 29, 1985, while entering the protected area through the processing center, the inspector noted that an individual ,

displaying an escort required badge was not properly searche THIS PARAGRAPH CONTAINS AND IS NOT FOR PUBLIC DISCLOSURE, IT IS INTENTIONALLY LEFT BLAN The inspector immediately notified securit Security performed an immediate search of the area and the individual was located within I4 minutes. The individual was then properly searched. The individual was in the presence of his

. required escort and did not enter a vital area but remained in a trailer located in the protected are The licensee immediately replaced the guard who failed to properly search the escorted individual entering the plan The guard was employed by the licensee's contractor, Burns Securi ty. The contractor released the guard from all future duties at TMI, terminated the guard's assignment immediately at TMI and escorted the guard off site. Licensee representa-tives immediately reviewed the event to determine if the

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incident compromised security at the plant, created a degraded security condition, or resulted in a security plan or procedure violation. The licensee's review noted that the event created a degraded condition and violated Security Procedure 1005.2, paragraph B.3.5 However, the licensee determined that the event did not result in a major degradation in security, and, therefort, did not require immediate notification to the NR c-j

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The inspector reviewed the licensee's incident report and agreed with the licensee's characterization of the even THIS PARAGRAPH CONTAINS AND IS NOT FOR PUBLIC DISCLOSURE, IT IS INTENTIONALLY LEFT BLAN Because the individual who violated the licensee's procedure was in continuous observation by his escort, and did not enter a vital area, the degradation in security was minor. The minor degradation was terminated once the individual was properly searched. The inspector reviewed the licensee's innediate corrective actions and found them to be acceptabl These actions included: terminating and replacing the security guard, conducting a search of the immediate area, conducting a hands-on search of the visitor and interviewing

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the escort to determine that the visitor was under continuous surveillance. The inspector considered the completed corrective action adequate. (289/85-21-07)

3.4 Operability of Source Range Instrumentation Over the last several nonths, the licensee has experienced failures of nuclear instrumentation source range channel N (NI-1). The problem initially appeared to be an electronic failure in the preamplication modules (preamp) of NI-1. The licensee replaced this preamp on several occasions but was unable to maintain channel operability. The licensee, in consultation with the vendor (Bailey Instruments) and Babcock and Wilcox, concluded that the instrument appeared to have partially lost conductivity of the inner shield somewhere in the signal cable run. The licensee systematically checked each connection from the detector to the reactor protection cabinets. The licensee found what appeared to be a shipping washer still installed that could have caused one connection

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not to be tight. Af ter ensuring all connections were electrically proper, the licensee was able to run the necessary calibration and alignment checks on NI- The inadvertent failure of HI-1 appears to be corrected; however, the licensee is still monitoring the channel closel The inspector independently reviewed the licensee's corrective actions. The inspector also discussed the problem with the I&C technicians who were troubleshooting the problem. From discussion with the technicians ar.d a review of the calibration data, the inspector concluded that the licensee has corrected the problem. Due to the fact that the licensee replaced various components on a trial and error basis, the root cause of the problem was not readily evident. The instrument had been monitored for the last week of this inspection period and had been responding properly. The inspector concluded that the licensee had resolved the problems with NI-l and the instrument was functioning correctl _ - I

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3.5 Significant Events On August 21, 1985, there was a partial loss of non-nuclear instrumentation and on September 7, 1985, there was a fire in the reactor's rod control system. These events were operationally significant in themselves, although they had minimal safety implications that would adversely affect restart. The TMI-1 Restart Staff's review of these events is described in paragraph 5 of this repor .6 Summary of Findings Overall, personnel stationed in the control room exhibited adequate control of daily activities, including problem areas that needed resolution. Licensee planning meetings stressed attentiveness to proceed safely with daily activities, including surveillance and maintenance, and to resolve any inter-departmental interface problems. Licensee upper management and quality assurance department personnel continued their detailed involvement in site activitie An extensive system of event report handling and management oversight was in place with event classification / reporting .

going beyond regulatory requirements. Event response by the operators was in accordance with applicable emergency procedures and the operators used their basic knowledge of plant design to properly assess unique circumstances and take appropriate corrective actio The security violation a9 pears to be an isolated cas Appropriate corrective retions were taken to return the source range channel to an operable statu . Surveillance Testing in prcparation for Restart 4.1 Review -

The inspector reviewed the surveillance test results of selected components / systems to verify that: test procedures were properly approved and adequately detailed to assure performance of a satisfactory surveillance test; test instrumentation required by the procedure was calibrated; and, the results satisfied Technical Specifications (TS) and procedural acceptance criteria or were otherwise properly dispositione The inspector reviewed the following surveillance tests and related data:

-- Source Range Channels NI-1 and NI-2 Calibration, SP 1303-7.2, performed on 8/25/8 '

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Internediate Range Channels NI-3 and NI-4 Calibration, SP 1303-7.1, performed on 8/24/8 Reactor Protection System Channel A Calibration, SP 1303-4.1, performed on 8/26/8 Reactor Protection System Channel B, SP 1303-4.1, performed on 8/27/8 Emergency Feedwater (EFW) Flow Instrument Calibration, 1302-6.3, performed on 12/19/8 EFW Flow Test from Condensate Storage Tank, 1303-11.42, (Quarterly) performed on 6/5/8 Emergency Feedwater Flow, 1303-11.53 (Monthly Calibration Check), performed on 6/3/8 The inspector also reviewed reactimeter " cold" checkout results and the licensee's test results evaluation for TP 415/1, "CRDM Breaker Shunt Trip Functional Test."

4.2 Findings 4. The inspector verified that inputs of delayed neutrons and decay constants for the reactimeter were consistent with the information provided by the-fuel vendor (B&W) Technical Document, " Physics Testing Manual for TMI-1 Cycle 5." The responses from the simulated inputs showed excellent agreement with analytically predicted values. The inspector will review reactimeter operation further if the reactor is made critical, using actual input from the Intermediate Range Channel NI- .

4. Surveillance Procedure (SP) 1303-11.53 for the EFW flow instrument requires a calibration check at 800 (+/-)16 gpm; however, SP 1302-6.3 calibrates the flow instrument to a tolerance of (+/-)11 gpm. It appeared to the inspector that this could result in an acceptable calibration check that was outside the tolerance of the calibration procedure acceptance

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criteri Licensee representatives reviewed this situation and determined that the calibration check tolerance (+/-16 gpm) was acceptable becau'se it represents only a 2% error which is reasonable for the design capability of the system. The indicator increments are 20 gpm (2.5% of span). The licensee representatives indicated that they preferred the calibration tolerance of 11 gpm to remain in effec The inspector-had no further comment _

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4. Also, during the restart readiness review (paragraph 12), the TMI-1 Restart Staff identified that 3 of 4 safety grade emergency feedwater (EFW) flow instruments indicated approximately 80 gpm (scale 0-800 gpm) flow during actual no-flow conditions (as indicated correctly by the fourth instrument).

Further, the discrepancy was documented on a priority 4 job ticket (lowest of 4 categories) which was in a "to be scheduled" status for work. Plant engineering also had an evaluation request from the maintenance department on the problem. Upon initial inspector questioning on the safety significance of the discrepancy, licensee representatives could not provide a definitive technical explanation as to why the discrepancy existed, and, therefore the safety significance could not be assessed. This was due to the fact that troubleshooting and engineering evaluation were not complet At that time just before the pending restart, licensee representatives indicated that the error signal at the low flow range is magnified more by the square root function on the error signal as '

opposed to the same error signal being imposed at the mid-to-high range where operation of the instrument would normally occur. Accordingly, licensee representatives expressed confidence in the accuracy of the instrument in its normal operating rang , Subsequent to the stay on August 29, 1985, of the Commission's Order pennitting restart, the licensee completed troubleshooting efforts and their engineering evaluation on the EFW flow indication

. problem. The results indicated that the differential pressure transmitter output current -

could change a measurable amount depending upon varying static hydraulic pressure as input to the transmitter. (This input is the differential pressure generated by a dynamic head measuring device"annubar.") Licensee testing confirmed that the static pressure on the transmitter was due to steam generator pressure (approximately 900 psig)

resulting from back leakage past the EFW check valve Further, the square root converter for the transmitter output signal has a low signal cutout function. This function provides a zero flow output for minor input differential pressure fluctuations of which annubar sensors are particularly susceptible to pressure variations. As a result, 3 flow channels read 80 gpm (with no system flow)

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because they were not properly aligned to compensate for the static pressure effect. The fourth channel, '\

which read 0 gpm, apparently was aligned such that '

the low signal cutout function took effect and provided a zero flow output indicatio Licensee representatives corrected this problem by perfonning a static pressure alignment on the transmitters in accordance with vendor instructions. The licensee representative stated that the vendor performed a static pressure alignment prior to shipment to the site and, therefore, licensee precperational testin'g of the instrumentation did not involve a static pressure alignmen The job tickets documenting the troubleshooting and evaluation effort of licensee personnel were in the closeout review process at the close of the inspection period. Further, the related information provided by the licensee was verbal and was unsubstantiated pending a review of associated ,

documentation. The adequacy of licensee documentation (preoperational testing and maintenance aspects) with respect to the static '

oressure alignment problem is unresolved pending further review by NRC Region I (289/85-21-01).

With respect to the EFW check valve leakage noted above, a related concern was described by IE Information Notice 84-06 regarding steam binding in the EFW system. The steam binding issue was

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reviewed by Region I in NRC Inspection Report 50-289/85-2 It was only recently that the licensee started checking for hot EFW piping on a shift basis. The results to date have not disclosed

. the presence of hot pipes. In light of the detected steam generator hydraulic pressure in the EFW -

discharge piping as noted above, it appears that the EFW flow control. valves and associated redundant

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block and control valves are relatively leak tight.

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This would prevent back flow or minimal flow such that heat losses are sufficient to prevent steam binding in the EFW pumps. As noted in NRC '

s Inspection Report 50-289/85-20, licensee actions are now adequate to detect hot pipes in the EFW syste .2.4 The functional test of the CRDM breaker shunt trip TP 415/1) was properly implemented. Test results agreed with test acceptance criteria or calibration tolerances. An appropriate licensee review was conducted for an evaluation of test result .

4.3 Sumary of Findings Preoperational and surveillance testing were properly implemented. Test results were in accordance with test acceptance criteria which properly reflected technical specification requirements. Licensee representatives could

have communicated better to the NRC TMI-1 Restart Staff their understanding of the technical problem and safety significance of the EFW flow instrumentation problem at the time of the

, p'ending restart (which was eventually delayed thereby providing more time for a complete evaluation of the problem).

c Onsite Followup of Events

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5.1 Scope of Review

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As noted in paragraph 3.5, the TMI-1 Restart Staff reviewed

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two significant events that occurred during this inspection

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g period to determine:

-- details regarding the cause of the event and event chronology;

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functioning of safety systems as required by plant conditions;

-- consistency of licensee actions with license requirements, approved procedures, and the nature of the event;

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-- radiological consequences (onsite or offsite) and personnel exposure, if any;

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proposed licensee actions to correct the cause of the i . event; and,

-- verification that plant and system performance are within the limits of analyses described in the Final Safety l

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For the partial loss of non-nuclear instrumention event of i August 21, 1985, the inspector discussed the matter with cognizant personnel and reviewed the following documents:

-- Control Room Operator's and Shift Foreman's Logs for the day of the event;

-- Licensee responses to IE Bulletin 79-27, " Loss of Non-Class-1-E Instrumentation and Control Power System Bus During Operation;"

-- Technical Design Report 172, " Evaluation of Loss of Power Supplies to ICS/NNI Systems;"

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Test Procedure 250/1.1, "ICS/NNI Power Failure Analysis Verification;"

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Applicable system drawings;

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EP 1202-40, " Total loss of ICS/NNI Power," Revision 6; .

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EP 1202-41, " Total or Partial Loss of ICS/NNI Hand Power," Revisions 6 and 7; l

-- EP 1202-42, " Total or Partial Loss of ICS/NNI Auto Power, Revisions 6 and 7; and,

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PIR 1-85-09, "ICS/NNI Subfeed Power Failure," dated August 21, 198 For the control rod drive power supply fire of September 7, 1985, the inspector discussed the matter with cognizant licensee personnel and reviewed the following documents:

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Control Room Operator's and Shift Foreman's Log for the day of the event;

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Plant Incident Report No. 1-85-10, dated September 7, 1985,(Draft);

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Operating Procedure 1105-9, Revision 30, October 31, 1984, " Control Rod Drive System; and,

-- Maintenance Procedure for Job Ticket No. CH 683, dated '

September 10,1985, " Power Up and Test CRDS After -

Transfer Switch Fault."

Details of the review and findings are discussed belo .2 Partial Loss of Non-Nuclear Instrumentation Event -

5. Event Chronology On August 21, 1985, a partial loss of non-nuclear instrumentation (NN1) occurred while the plant was in the hot shutdown condition with the reactor coolant system (RCS) pressure at 2155 psig and RCS temperature at 533 F. At 1:38 PM an operator pulled out the makeup tank level recorder (MU-14-LR) to the

" parked" position to monitor'and trend tank level indication. As a result of this action, a cable ]

shorted to ground, tripping a subfeed breaker ;

(makeup auto power) in the NNI system. At the time of the occurrence, it was not evident that the makeup tank level recorder had initiated the partial loss of NNI. Various annunicators alanned, the most

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significant of which was the " Loss of ICS/NNI Power" annunicator which keyed the operators to look at the

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6 subfeed status (white) lights on the panel center left (PCL) (in direct view of the operators). The light designated " Auto / Hand Power Subfeed" was the only light out indicating a problem with a subfeed

.M breaker. The other'subfeed lights were for those circuits designated in Figure 1. Each of the 6 circuits had corresponding unique labels (for human factors considerations) from which each instrument indicator was labeled to indicate those instruments affected by a power failure to NNI. Due to the somewhat unusual sequence of events, operators

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decided to independently verify affected instruments. They accomplished this within five minutes after the event starte Within ten minutes, the operators were able to

, identify the specific subfeed circuit (makeup auto

" e power) that was de-energized by review of the

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't ICS/NNI power monitor panel in the relay room which

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is located one floor below the control room. The e loss of this subfeed breaker caused a loss of indication for reactor coolant pump seal injection

,6 : ,0 flows, reactor coolant system letdown temperature and flow, and HPI flow transmitters MU-23-FI 3 and In addition, MU-V-3, RCS letdown isolation

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valve, cycled shut. With MU-V-3 shut (i.e., no

, letdown flow), the level in the pressurizer began to increase from its initial 100 inch mar ; Concurrently, the operators started to implement the applicable emergency procedures for the event. The

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procedures provided for a means to override the

• e interlock that caused MU-V-3 to go closed. By 2:00 PM operators lifted a lead to open MU-V-3 and

. pressurizer level was restored to its initial valu By 2:30 PM the makeup auto power was partially -

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restored with the fault isolated to an individual

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cabinet (No. 6). Troubleshooting and fault

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- (I&C) technicians lifting leads to various components in the system. By'3:35 PM the fault was

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o isolated to the makeup tank' level recorder. Further

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inspection of the recorder and associated cables

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As a result of the event, pressurizer level

increased approximately 40 inches before being

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restored to its initial hot shutdown leve There

'f was no substantial pressure change in the RCS; and, therefore,ithe PORV and safety valves were not challenge ,

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FIGURE 1 NON-NUCLEAR INSTRUMENTATION SIMPLIFIED POWER DISTRIBUTION

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M ore Flood

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AUTO Intermediate Cooling

_, Decay Heat Removal

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Makeup and Purification A Chemical Addition A Spent Fuel Cooling Reactor Building Spray A ntegrated I Control System ACore Flood HAND A Decay Heat Removal A Reactor Building Spray

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A iakeup and Purification O Spent Fuel Cooling ATA A lntegrated Control System A

HEX (Pressurizer; OTSG)

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A HEY (Pressurizer; OTSG) '

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AUX (Emergency F dwater)

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n FAN

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5.2.2 Licensee Review / Findings The licensee documented its review of the event along with planned corrective actions in Plant Incident Report (PIR) No. 1-85-09, dated August 21, 1985. The PIR provided a sequence of events which included any resultant automatic actions. Further, the PIR documented the root cause of the event (faulty cable), corrective actions and lessons learned. The licensee replaced the faulty cable and inspected other connector cables in the control room to determine if there were similar problem Followup actions included the establishment of a preventive maintenance action to periodically check the integrity of similar connector cables and to review the applicable emergency procedures for

. adequacy of operator information on loss of either individual subfeed circuits or all ICS/NNI powe At the close of the inspection period these items were complet . Preliminary NRC Findings on Immediate Post-Event Review Because of the significance of the event, the NRC TMI-1 Restart Staff initiated a review to determine any safety implications that would preclude restar This review consisted of: interviews with the operators that experienced the event, review of

, applicable emergency procedures and PIR 8-85-09; and walkdown of affected instruments and indicators in the control room and cable spreading roo Subsequent to that review, the inspector determined that there were no findings that would preclude a-safe restart. However, the inspector raised the following question What specifically caused MU-V-3 to go shut?

-- Was the human factors labeling adequate to identify specific instruments affected by specific subcircuit failures and were procedures in place sufficient to complement any shortcomings in this area?

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What transient would occur on a loss of NNI power (totally or partially) if the plant had been operating at the time?

-- Are the reactor protection system (RPS) and

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engineered safeguards actuation systems (ESAS)

I sufficiently isolated from NNI to prevent adverse conditions from affecting RPS and ESAS operability?

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-- Is the training program adequate with respect to ICS/NNI modifications and procedure changes?

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What instruments are powered from NNI and what safety functions, if any, do they perfonn?

The results of the more detailed review are discussed belo . Additional Review - NRC Findings 5.2.4.1 Training Program and Operator Performance The inspector focused on the training associated with partial and full loss of the ICS/NNI system, in particular on training received by operators on emergency procedures associated with loss of ICS/NNI. The inspector found that the required knowledge level was detailed enough that an operator would gain a good understanding of this complex system. The licensee was starting to use their Basic Principles Trainer (BPT) to aid the operator in developing the basic knowledge on how the integrated control system (ICS) processes different signals. The use of the BPT supplemented ICS/NNI trainin ,

This review also identified that the listed source of information to be covered in the lecture was the emergency procedure itself. In general, the emergency pncedures were sufficiently detailed that coupled with other lesson plans, there was adequate assurance that operators could respond to a total or partial loss of NNI/ICS. However, the emergency

. procedures were found to be weak in the area of partial loss of power due to the opening of a system -

subfeed breaker as was actually experienced on August 21, 1985. The licensee has now revised EP 1202-40, 41, and 42~to identify the specific instrumenh associated with each subfeed circui Interviews with the operating crew that was involved with the event were conducted to determine how the operators responded and coped with the event given that the procedures lacked specificity for loss of a subfeed breaker. The inspector concluded that even though the procedures were weak for a loss of a subfeed breaker, the operators were able to respond and maintain the plant in a safe condition during the event. The operators were appropriately cautious given the unique event conditions, and their actions were properly oriented toward an independent assessment of plant conditions in order

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to implement the appropriate corrective action. The modifications that were made to the plant as a result of the Crystal River event (IEB 79-27) were a significant aid in quickly identifying the portion of the NNI/ICS system that was los .2. Emergency Procedures

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Overall the emergency procedures were quite detailed in anticipation of total loss of NNI or partial loss of the NNI with respect to loss of "AUT0" or " HAND" circuits. Affected instruments were listed in the procedures along with backup instrumentation. The provisions for overriding the MU-V-3 interlock were anticipated and documented in the emergency procedure (1202-40).

However, the inspector identified that no procedure existed for a Loss of " HEY," " HEX," and " AUX" circuits. The instruments powered by these subfeed circuits are steam generator level and pressure and pressurizer level. Further, the inspector determined that these instruments are backed up by safety grade indicators. The licensee acknowledged this and committed to generate the necessary procedures or revise current procedures by October 1985. This is unresolved pending completion of licensee action and subsequent NRC Region I review (289/85-21-02).

The licensee's review also identified that the .

existing emergency procedures were weak in the area of addressing partial loss of power due to opening a system subfeed breaker. Affected instruments need

. to be listed by subfeed circuit. The licensee rewrote the procedures to correct this proble .2. Design Review 5.2.4.3.1 From this review the inspector noted that several key parameters were supplied by the ICS/NNI syste The power for the ICS/NNI system is from one single load center labeled "ATA" (see Figure 1). A failure of the ATA load center would remove, in part, indication from the control room for spent fuel cooling flow, high pressure and low pressure injection flow, core flood tank level and pressure, borated water storage tank level and reactor building spray flow. These parameters either directly or indirectly affect operator actions specified in the emergency procedures. Licensee representatives acknowledged the finding and stated that a review would be performed to ensure that the loss of these instruments would not have an adverse effect on operator ability to respond to an

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emergenc .._ _

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17 .

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During the inspection period a licensee operations engineer completed that review. He identified where these instruments are referred to in ATOG procedures, and he provided an analysis on how redundant loc ~al or other safety grade parameter indications could be used as an alternate means of parameter verification or indication. The engineer indicated that the results of his review would be factored into the licensed operator training progra This design meets the current criteria (Category 2)

in Regulatory Guide (RG) 1.97, Revision 3, for instrumentation to assess plant conditions during or following an accident. Per RG 1.97, Category 2 instruments do not need redundant power supplies or redundant indication - just a highly reliable power source. However, the inspector expressed concern that the loss of these instruments would be an unnecessary distraction to the operators in performing their safety functions during an accident condition. Since the Office of Nuclear Reactor Regulation is reviewing licensee implementation plans for RG 1.97, this matter will be referred to NRR for additional evaluation (289/85-21-03).

5.2.4.3.2 In addition, the inspector noted that TDR 172 and the test procedure did not address the effects of interlocks that are associated with the ICS/NNI system. Discussions with the licensee's lead Instrument & Control (I&C) engineer demonstrated that even though the interlock analysis was not formally documented, the interlocks were reviewed and considered in the development of the licensee's

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procedures as a result of the Crystal River modifications. The inspector reviewed and discussed each interlock with the I&C engineer to determine its affect on the plan No safety concerns were identifie However, the inspector concluded that a current single source document did not exist that could address the failure effects of ICS/NNI on the plant considering instrument failures, interlock actions, and instruments used in emergency procedures that are not backed up by safety grade instrumentatio This matter is being referred to NRR in conjunction with the other above-noted finding .

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5.2.4.3.3 During the review of the human factors labeling arrangements of instrument to circuit designations, the inspector questioned the use of the triangular

"S" label associated with the subfeed breaker (light that went out during the event). The Auto and Hand Power circuits (designated "A" and "H" respectively)

actually feed all the "S" designated circuit Since the "A" and "H" circuits are each a smaller subset of the "S" designators, it would appear that

"S" instruments should be labeled either "A" or "H" for a more specific circuit designation. Licensee representatives could not immediately determine why the "S" designator was used, but they committed to revise the labeling scheme to more clearly designate related subfeed power circuits to each instrumen Since the labeling revision involved a modification subject to appropriate review and approval, licensee representatives anticipated that the new labeling installation would be completed by January 198 The inspector noted that, in the interim, the revised emergency procedure provides operators with actual information for instruments associated with particular subfeed power circuits. The installation'

of the revised labeling for control room instru-mentation is unresolved pending completion of licensee action (289/85-21-04).

5.2.4.3.4 The inspector expressed concern to the licensee that the drawings being used by the plant were difficult to read. The licensee representative acknowledged this and stated that this area is being reviewed in conjunction with the vendor information handling issue (one of the Salem ATWS actions). In addition,

- the licensee independently is developing a simplified drawing on ICS/NNI power supplies that-will address this concern from an operator training aid perspectiv .2. Licensee Special Report ,

Because of the number of previous events involving loss of NNI power at other B&W reactors and because of NRC staff interest in the August 21, 1985, event, the licensee submitted a special report, dated

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September 16, 1985, from H. Hukill, GPUN, to Dr. Murley, Region I Administrator. The inspector reviewed that report and found that it accurately reflected the facts of the event. Froblem areas and corrective actions in that letter were more comprehensive than the initial plant incident repor '

.

However, the report did not address the problems in the design area noted by the inspector in paragraphs 5.2.4.3.1, 5.2.4.3.2, and 5.2.4. Licensee representatives were apparently satisfied with previo'is design reviews for modifications and procedure changes that resulted from IE Bulletin 79-27. They indicated that in general these modifications proved to be an aid to the operators during the August 21 event. -The inspector acknowledged the above and stated that the licensee's review was adequate. He noted, however, that in the future the licensee should not be reluctant to question the design during reviews of this typ .2.5 Summary of NRC Findings on Partial Loss of NNI Event The licensee's training program met its objective to heighten operator awareness of problems associated with a loss of power to NNI. The basics were provided in order for the operators on August 21, 1985, to recognize the unique aspects due to the partial loss of power and to properly control the plant along with isolating the initial fault within a reasonably short period of time. The emergency procedures were useful in providing a methodology to override an interlock. However, there was a procedure weakness in that the procedure did not list instruments according to subfeed circuit Also, subsequent review identified a lack of procedures for certain subfeed circuits, but this

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did not adversely affect operator actions during the August 21, 1985, even It appeared that the human factors labeling was not relied upon by the

. operators to confidently identify affected instruments. This necessitated their conducting an instrument-by-instrument assessmen In retrospect, the labeling was somewhat confusin The NNI system is subject to a single failure; namely, the loss of the ATA. Previous modifications adequately corrected adverse controller response on loss of NNI power and provided for safety grade backup instruments to achieve cold shutdow Although not well documented, when applicable procedure revisions were issued as a result of the above noted modifications, engineering department personnel reviewed affected instrument interlocks (which, in general, go into effect on loss of power)

and the results indicated that there were no adverse effects on the plant. There is no updated failure modes and effects analysis in the one document that provides an overall review of a loss of NNI power even Further, certain instruments relied on,

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either directly or indirectly in' ATOG procedures,-

are subject to a single failure, but they are backed up by local indicators or other parameter-verification means. These backup methods are now _

being documented and will be incorporated into the training program, but they do provide an unnecessary distraction to operators during their response to event Overall, the response of the operators to the event was excellent. The design review and proposed changes are adequate for restar .3 Control Rod Drive Power Supply Fire 5. Event Chronology On September 7,1985, the licensee commenced a surveillance procedure (SP 1303-7.1) to perform a-calibration check' and interlock test of the intermediate range channe Paragraph 8.7.8 of SP 1303-7.1 required the operator to transfer a regulating rod group to the auxiliary power supply ,

for the interlock test (rod out motion inhibit on

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high startup rate in the intermediate range of nuclear instrumentation). The operator performed a step out of sequence but, on correcting himself, the

" Diamond" control logic permitted the transfer that eventually led to the fir . When the transfer occurred at approximately. 3:58 PM, the Diamond-control power lights flickered along with Group 5 and 6' control lights being on with only Group 5 selected. The operator attempted to .

- transfer Group 5 back to the manual power supply but a fire alarm for the relay room occurred. Operators were dispatched to the relay room along with the fire brigade. The shift supervisor ordered the reactor tripped and the rod control system was de-energized by opening breakers'on the G and L F busses. The fire was'put out within 7 minutes (4:05

,s PM). At 4:25 PM operators completed followup actions for a reactor trip per AT0G procedure 1210-1

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and emergency procedure 1202-31. By 5:00 PM the 1 fire watch in the relay room was secured and the cardox system was returned to service. The cardox n system did not' actuate because temperature in the j room did not reach the actuation temperature. At

- 6:10 PM the.0perations Manager discussed the event

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with the Senior Resident Inspector who was also informed-that, because a reactor trip occurred, a 10 CFR 50.72 report would be made to the NRC Operations

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Center. The report was made at 6:14 PM and the

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followup licensee event report is pendin '

5.3.2 Licensee Review / Findings The licensee initially issued Plant Incident Report No. 'l-85-10, dated September 7,1985, as an initial documentation of the sequence of events with the investigation under review. By September 10, 1985, the licensee issued a special maintenance procedure for JT No. CH 683. This procedure was developed to troubleshoot the control logic circuits after the damaged power transfer switch was repaired. The results of that troubleshooting / testing were that, in addition to the identification of power supply blown fuses as a result of the event, the licensee identified a short between two adjacent contact leads in a control logic relay (K-171). The short was apparently due to a foreign piece of metal within the switch. This resulted in control power being fed to the Group 6 transfer control rela With the normal DC power supply not properly synchronized to the auxiliary power supply and coupled with the opening of contacts on the power transfer switches for the normal power supply, this apparently resulted in high currents for a long period of time resultir.g in the fir The troubleshooting also identified a latching relay (K-108) in the latched position. As expected, testing resulted in the Group 8 power transfer switches (without DC current transferred) also actuating during the test but this did not occur on September 7, 1985. Licensee representatives suspect a manual inadvertent latching of the relay switch during post-event inspection of the syste .

. As of September 16, 1985, the K-171 relay was replaced and post-maintenance testing was completed along with the conduct of related control rod drive surveillance testin . NRC Findings Operator action in response to the event was timely and correct in isolating all power sources to the control rod drive power supply system. The out-of-sequence steps by the operator prior to the event apparently did not contribute to the event. This was confirmed by repeating the same out-of-sequence steps in the licensee's troubleshooting / test procedur The special maintenance procedure was properly implemented and it provided sufficient information as to the probable cause of the event. Licensee quality control inspectors monitored licensee

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activities during the implementation of the pro-cedure. This was also periodically witnessed by various levels of management in the operations and maintenance department. Adequate technical support was provided by plant engineering and the licensee used the services of B&W in their troubleshooting efforts. Overall, the special evolution was conducted in a deliberate and methodical manner under the control of a cognizant senior test enginee At the end of the inspection period, the licensee was preparing to issue a Licensee Event Report in accordance with 10 CFR 50.7 Further, before restart, the NRC will review control rod surveillance testing performed subsequent to the special maintenance procedure implementation. This matter is unresolved pending NRC review of the licensee's LER and test data for the control rod testing before restart (289/85-21-05).

5.4 Summary of Event Followup For the two events discussed above, licensed operator responses to these events were correct and timely. Applicable emergency procedures were properly implemented. Followup corrective actions by licensee representative were, in general, sound and appropriate for the circumstance The resident inspectors questioned why an information report was not provided to the Region I office since the resident inspectors were not on site at the time of the even Licensee representatives indicated that, in retrospect, this was an oversight and that the event should have been reported to the NRC resident inspector's office for information. The resident inspector concurred with the licensee's characteriza-tion of the matter. Based on the inspector's past experience, the licensee has been conscientious in making information reports (although not formally required) to the NRC resident office. The inspectors had no further comments on this matte . Refueling Cavity Water Seal An inspection was conducted to evaluate the potential for and consequences of a failure of the refueling cavity seal. This inspection is a followup to the inspection conducted to closeout NRC Bulletin 84-03, " Refueling Cavity Water Seals" (Inspection Report 50-289/85-08). This inspection was performed using the guidance provided in the NRC's Office of Inspection and Enforcement (IE) Manual, Temporary Instruction 2515/6 s

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The inspectors verified that the licensee has identified the

. worst-credible seal failure. The TMI-1 seal plate assembly is a flat annular steel plate that fits.around the upper reactor vessel flange and bridges the gap between the reactor vessel and the transfer canal floor. The plate is sealed along its inside and outside edges by rubber gaskets and is bolted in place by 72 seal plate fasteners. Additional pressure to retain the seals and to increase their effectiveness is provided by the head of water

during refueling operations. This design makes a major gasket failure very unlikely. Nevertheless, the licensee calculated the maximum credible. leakage to be approximately 4700 gpm. This is based on a loss of seal along 50% of the inner gasket circumference. The licensee has evaluated the consequences of such a failure. This evaluation shows that an operator handling fuel would have more than 25 minutes from the receipt of the low level alarm to position the fuel over an appropriate storage location, as identified in the abnormal procedure, and start lowering the assembl To provide instructions for the operators in the event of a rapid decrease in fuel transfer canal water level, the licensee has in place an Abnormal Procedure 1203-43, " Transfer Canal Seal Plate Gasket Failure." This procedure provides instructions to insure that fuel ~ components remain shielded with water to minimize the extent of spillage to the reactor building sum The seal plate and gasket installation procedure requires that the final torquing pass sequence of the seal plate fasteners be redone after major traffic on the seal plate (such as caused by head detensioning) and after draining before any subsequent refil This is to minimize the leakage during filling and draining when hydraulic pressure is lo In the event of a complete draindown, no fuel in storage would be uncovered since the core and the fuel in storage are both below the fuel transfer seal plate elevation. With no operator action, the level in the spent fuel poo! would decrease over a two-hour period and stop with 11/2 feet of water above the stored fue The Abnormal Procedure specifies, after storing any fuel in transit to the nearest available storage space, to isolate the spent fuel pool from the fuel transfer canal and to drain the fuel transfer canal in order-to minimize spill into the reactor building sum The maximum makeup capacity would be the recirculation of the t reactor building sump. This could be done from the control-room in a very short time and would provide makeup in excess of 3000 gp Based on the low potential for massive leakage and the time available for other operator action, the use of this makeup path is not likel In summary, the licensee properly implemented the actions addressed in NRC Bulletin 84-03 and the Temporary Instruction 2515/66. The design of the refueling water cavity seal appears to be sound in that water head pressure provides additional seating pressure for

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the sea Further, design pool elevations preclude the uncovery of the spent fuel in the spent fuel pool Licensee procedures adequately address off normal occurrences during refuelin . Review of Licensee Investigation On June 6, 1985, a licensee employee in the maintenance department, along with his union Vice President, met with the Vice President and Director, TMI-1, to discuss items considered by the employee to be potential safety issues. In response to the employee's concerns, a senior individual outside the plant staff was assigned to fully investigate these potential safety concerns. The NRC was informed of the meeting and kept abreast of the investigation finding The completed investigation results were reviewed. This review showed the three main concerns of the employee were: (1) the assignment of an unqualified individual to a fire watch, (2) a weld repair incident in which a supervisor directed a welder to make a weld to coverup a gouge in a pipe before quality control (QC) had a chance to inspect it, and (3) apparent improper implementation of a maintenance procedure for flexitallic gasket installation *

The investigation identified no safety problems. The fire watch issue resulted from an administrative error and the individual ,

assigned fire watch duties was qualified. The welding concerns resulted from a communication problem and there was never a safety concern or an attempt to conceal information about the work. The flexitallic gasket installation procedure, however, did need to be upgraded. As a result of the investigation observations and findings, the investigator proposed certain recommendations and suggestions. Internal memoranda show action has been taken to respond to these recommendations and suggestions. In sumary, licensee action included:

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-- initiating correspondence and discussion within the -

Maintenance Department to improve internal communications on problem areas and to reemphasize individual responsibilities for documenting any quality control deficiencies through the use of quality deficiency reports; and,

-- initiating a revision to the flexitallic gasket procedure to make it more usable in the field along with providing training on the proper installation of such gasket The concerned employee was given a copy of the investigation report and the licensee's internal memorandum stated that the individual basically agreed with the report and its conclusio The TMI-1 Restart Staff review of this matter verified that no violations of any regulatory requirements appeared to have occurred, and the licensee made a major effort to resolve the potential safety concerns of an employee. In addition, the licensee has taken action to implement recommendations and suggestions to improve the overall program for responding to employee concerns. This matter is considered close _

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8. TMI Action Plan Equipment Installation / Modification The inspector reviewed six TMI Action Plan items that included equipment installation / modification requirements applicable to TMI-1 to verify that the licensee's completed actions were in conformance with NRC requirements and licensee commitment For each equipment installation / modification the inspector also verified that equipment changes were properly approved and controlled, that as-built drawings were changed to show the equipment changes, and that necessary procedure changes were mad In addition, the inspector verified that preoperational testing was complete, that equipment was calibrated, if applicable, that the equipment was operable and that operating procedures were being use The scope of this verification consisted of a review of previous NRC Region I inspection reports that described the staff's earlier partial verification of these items. The licensee's implementation of these equipment installation / modification items had been inspected over a period of several years while NRC requirements were evolving and while licensee commitments were being evaluated by the Office of Nuclear Reactor Regulation and in some cases adjudicated during TMI-1 restart hearings. Therefore, the purpose of this review was to determine whether previous NRC inspections had verified sufficiently the-6cceptable implementation of these items. The TMI Action Plan (ihP) items reviewed and the previous

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NRC Region I inspections at TMI-1 regarding these items are listed belo TAP Item item Description Previous Inspections II. Direct indication of relief- 80-04, 80-05, 80-20, and safety-valve position 81-04, 81-22, 81-24, 81-28, 82-19, 82-21,

. 82-26 II.E. , 81-28, 82-01,

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Emergency power supply for pressurizer heaters 82-16, 82-19, 82-26, 83-01, 83-22, 83-25 II.E. Dedicated hydrogen penetrations 80-04, 80-06, 80-17, 81-22, 82-06, 83-02, 83-05 II.F.1(4) Containment pressure monitor 83-06, 83-12, 83-16, 83-32, 83-34, 84-29 II.F.1(5) Containment water level 83-11, 83-12, 83-16 monitor II.F.1(6) Containment hydrogen monitor 83-12, 83-16, 83-23, 83-25, 84-02, 84-06

Based on this review of previous NRC inspections, the inspector determined that licensee implementation of the above TAP items had been verified to be acceptable in all respects with one exceptio The licensee's original design and procurement documentation to assure compliance with equipment qualification requirements associated with TAP item II.D.3, which required direct indication of relief- and safety-valve position, was identified as an item of concern during NRC Inspections 50-289/80-04 and 50-289/80-0 The concern at that time was that the proper requirements were not specified in licensee documents, in part due to inadequacies in the licensee's then-existing system for classification of safety-related equipment and components. This item was later found acceptable and closed during Inspection 50-289/81-22, but the staff's basis for closure did not appear to be correctly describe However, the environmental qualification (EQ) requirements specified for TAP item II.D.3 were subsequently superseded by NRC rulemaking, specifically the issuance of 10 CFR 50.49. On a sampling basis, inspectors verified proper seismic and equipment qualification for restart modifications in NRC Inspection Report 50-289/83-16. However, the subject components were not selected in the sample. The NRC staff is planning special inspections of all licensees to verify compliance with 10 CFR 50.49, and the equipment qualification aspects of relief- and safety-valve position indication installation will be verified during the TMI-1 EQ inspection (289/85-21-06).

9. Licensee Event Report (LER) In-Office and Onsite Review The inspector reviewed LER 85-001-0, which was submitted to the NRC on July 26, 1985, pursuant to 10'CFR 50.73. LER 85-001-0 described an inadvertent emergency safeguards actuation system (ESAS)

actuation that occurred on June 25, 198 The ESAS actuation occurred during performance of a surveillance test when an operator -

attempted to perform two steps of the procedure in the reverse sequence. Based on resident office review of the LER, the -

inspector determined that corrective action discussed in the licensee's report was appropriate, that the information satisfied reporting requirements and that there were na generic issues. In addition, the inspector detennined that the event is not appropriate either for classification as an Abnormal Occurrence or for Licensing Board, Appeal Board or Commission notificatio However, because the event involved procedural noncompliance (not following the approved surveillance procedure in the step-by-step sequence), the inspector conducted onsite followup to the even The initial NRC review of the event was conducted on June 25, 1985 immediately following the ESAS actuation and initial licen.ee response and restoration actions to that event, as documented in NRC Region I Inspection Report 50-289/85-19 (289/85-LO-01). LER 85-001-0 identified two factual errors in the inspector's initial understanding of the cvent. First, the cognizant system engineer, although present in the control room, was not consulted by the

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operator or shift foreman prior to the operator's attempt to perform the two steps out of sequence. Hence, the cognizant system er.gineer did not contribute to the cause of the event as originally thought by the inspector. Second, the emergency diesel generator which started upon ESAS actuation was not secbred "about a minute after initiation" as originally thought by the inspector. Instead it was secured in a controlled shutdown sequence. The makeup pump and decay heat removal pump were secured about one minute after initiation, but the diesel ran unloaded at 900 rpm until it was idled down, then secured and returned to standb Based on the onsite review of the event during this inspection, the inspector verified the nature, impact and cause of the event and the actions taken or planned by the licensee. As noted above, the event involved procedural noncompliance by licensed operator However, the event had no actual or potential adverse safety impact, operator response was prompt and correct and licensee followup actions, including corrective actions and reporting, were excellent. The inspector verified that sound corrective actions were being taken both aggressively and in a professional manne The licensee's initial internal report of this event (Plant Incident Report 1-85-06) and the subsequent external report (LER 85-001-0) demonstrated an engineering evaluation that was performed thoroughly and described with appropriate candor. The inspector stated that no further NRC action is planned regarding this event and that this item 289/85-LO-01 is close . Review of Licensee Strike Contingency Plan A review of the licensee's strike contingency plans was performed to verify that an approved plan was in place and properly addressed the necessary function to assure that the plant could be operated safel The inspect.or obtained and reviewed the licensee's contingency plan dated April 18, 1985 The plan was composed mainly of three .

section watchbills listing the positions that would be manned during a strike. The watchbills were an enclosure to a cover memorandum from the Onsite Human Resources Manage The inspector verified that adequate numbers of personnel were identified in the area of plant management, plant operations and maintenance including necessary personnel required to perform surveillances and calibrations, chemistry and radiation protection, and securit The inspector noted that one individual listed on the watchbill required to have a reactor operator (RO) license by that position was not in possession of an active license. The inspector discussed this with the licensee's representative who was aware of the situation but stated that the watchbills are only updated as needed. The inspector did note that the individual in question had a current license when the bill was update.d and would have been available during the period when union contracts were being negotiate '

The inspector discussed with the licensee's representative refresher training and familiarization of licensed personnel and non-licensed personnel who routinely do not stand these watche Personnel who hold a license are required to stand monthly proficiency watches.. However, personnel who are designated to stand non-licensed positions such as auxiliary operator (AO) are

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not required to stand proficiency watches. The inspector reviewed the list of people designated to perform the function and noted that several-individuals who were qualified R0s or in training for R0 positions never performed the functions of an auxiliary operator. The inspector questioned their ability to properly function in this position since they had not received formal training. The licensee representative stated that if a strike would occur that the more experienced personnel (approximately two individuals per shift) listed as auxiliary operators would be used initially to perform the duties of the A0 The other personnel listed would be put on shift allowing these individuals to develop the necessary familiarization and training to properly assume the A0 position. The licensee stated that if in the opinion of the Vice president and Director TMI-1, in consultation with operations management, the depth of expertise and experience was insufficient l to maintain the plant safely during a strike, the plant would be shutdown. The inspector acknowledged this approac The licensee's contingency plan was ~ reviewed to verify that the plan adequately addressed procedures to assure unhampered delivery of goods such as food, diesel fuel, and assure access to the plant by personnel necessary to maintain proper staffing. Through discussion and review'of the plan, the inspector determined the plan adequately addressed this aspect of preparation for a strike.

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In general, the strike contingency plan included appropriate provisions to assure that qualified personnel are assigned to key operating stations and that sufficient logistical support is provide .

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11. Inspection Report Clarifications During this inspection period licensee representatives completed their review of NRC Inspection Reports (IR) 50-289/85-19 and 85-20 and they verbally reported to the NRC resident office' areas that needed clarification to assure an accurate perspective of the

! fact Paragraph 5.3.3.1.2 of IR 85-20 erroneously reported that the l mechanical portion of the redundant block and control valves for emergency feedwater system discharge headers was complet In l actuality, a block valve on the "A" header needs to be installed

! and the preaccident EF-V30A/B valves need to be replaced. What was l intended to be stated was that the mechanical portion was intact

! and could be made operational by manual mean ,

L k

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At the bottom of page 23 of IR 85-19, the last paragraph erroneously reported that the backup controller for EF-V30A/B is an

" automatic" controller. It is only a manual loader device that is controlled by operator action on proper actual level from safety grade level indications for both steam generator Paragraph 6 of IR 85-20 defined the steam generator plugging criteria as defined in NUREG 1019. Once Through Steam Generator (OTSG) plug ratio was improperly characterized in this inspection report. The three to one pl.ugging ratio between OTSGs is not applicable until the total number of tubes removed from-service exceeds 2,000 tubes. The licensee also plans to clarify this in their submittal of.a related Technical Document Repor The above noted items stand corrected or clarified as noted abov The staff's previous findings and conclusions regarding those items, as described in Inspection Reports 50-289/85-19 and 85-20, remain unchange . Restart Readiness During the inspection, the resident inspectors assisted by region based inspectors continued the review of equipment operability (started in NRC Inspection No. 50-289/85-12) in selected areas to assess the readiness of the plant for startup. The selected areas inspected included safety related building spaces; outstanding licensee identified items in the surveillance, maintenance and modification areas; outstanding NRC inspection findings; and selected valve lineups. The objective was to identify equipment 4 operability problems that could adversely affect safe operation of the facilit The results of this review are documented belo .1 Safety. Related Building Spaces

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Periodically, the inspector reviewed safety related building spaces to identify any loose equipment, scaffolding, or other problems such as fire hazards / housekeeping that could adversely affect the operability of safety related equipment in adjacent area Shortly before the pending restart of August 29, 1985, selected areas of the following safety related buildings were inspected: reactor building; auxiliary building; fuel

. handling building; intermediate building; diesel generator building; and control buildin In general, equipment storage was satisfactory and in accordance with the licensee administrative procedure However, during the reactor building inspection, a core flood tank level indicator had an active leak with substantial boron

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encrustation. The licensee was responsive and corrected this ite v m

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12.2 Outstanding Licensee Identified Items The inspector reviewed selected portions of the licensee's applicable corrective action tracking systems to detemine if any adverse condition for safety related equipment operability existed. The inspector's review included tracking systems for -

open maintenance job tickets, open exceptions and deficiencies

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(E&Ds) associated with technical specification surveillances, and open plant modification incomplete work list item ,

The inspector reviewed the open job tickets and discussed all work that had been classified as priority one, two and thre ~ At the completion of the review, the resident inspector i identified the zero flow problem with the emergency feedwater system flow indicators. Followup review was conducted jointly by the startup and test inspector and the resident inspector (see paragraph 4). Of the priority two and three work, the

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-i inspector determined that the work required by these jobs -

would 'not have an . adverse affect on the plant safety if not completed prior to returning the plant to operatio The. inspector reviewed all E&Ds noted by the licensee for all

- current surveillances. From this. sampling the inspector determined that the licensee was properly conducting required

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surveillances and none of the noted deficiencies or exceptions would adversely affect-plant safet The incomplete work items list (IWL) was reviewed. The inspector discussed the IWL with licensee representative The licensee adequately resolved or addressed each item on the IWL to ensure that no adverse condition would exist due to an item remaining ope ,

The inspector found no conditions that would adversely affect - -

plant , safety in these areas or inconsistencies with regulatory requirement t 12.3 Outstanding Inspection Findings

, The inspector reviewed the Region I file of outstanding 4 '

inspection findings to identify any equipment operability problems that would adversely affect safe operation of the

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- facility. No such conditions were identifie .4 Valve Lineup Verifications

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L As part of the validation of the TMI-1 readiness for~ restart, i the NRC TMI-1 Restart Staff independently verified the L position of safety related valves. The shift inspectors, with-

" the aid of auxiliary' operators, verified the position of

! valves listed in the following operating procedures:

1.

! -- Operating Procedure (0P) 1104-1, " Core Flooding System;"

F -- OP 1101-3, " Containment Integrity and Access Limit;" and, i

+

- + , - - - = g,- w v u -r-=q,-,-,me,-~.w-,,,,,%.wwvy-- , ---.-,r-vrwwww--,ev---mmy,,,--,w--w-,,,-m,-wr-w--. vr.,--e---.-,,,-------,,--,v- - - - -

--wowv me-&,- ww~-v

-

-

,

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--- OP 1106-3, " Emergency Feed."

The valve lists were determined to be accurate and valves checked were in their proper positio Due to the continued delay of restart (U.S. Court of Appeals for the Third Circuit stay of the Commission's restart

' decision), this effort was stopped but the review would I normally include additional safety related system No conditions were identified that would preclude safe operation of the facilit . Exit Interview The inspectors discussed the inspection scope and findings with licensee management at the exit interview conducted on September 16, 1985. The following personnel attended the final exit meeting:

--

J. Colitz, Plant Engineering Director, THI-1

-- D. Hassler, Licensing Engineer, TFD

-- H. Hukill, Vice President and Director, TMI-1

-- C. Incorvati, QA Audit Supervisor

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R. Maag, Operator Training

-- R. Neidig, Communications

-- V. Orlandi, Lead 18C Engineer

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S. Otto, Licensing Engineer, TFD

-- J. Paules, Shift Foreman

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H. Shipman, Operations Engineer, TMI-1

-- J. Stacey, Security Manager

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R. Toole, Operations and Maintenance Director, TMI-1 As discussed at the meeting, the inspection results are sunnarized in the cover page of the inspection report. The licensee representatives indicated that none of the subjects discussed contained proprietary information. The inspector noted at the exit .

interview that there were no obstacles to safe restart of the uni Unresolved items are matters about which information is required in order to ascertain whether they are acceptable items, violations or deviations. Unresolved item (s), discussed during the exit meeting, are documented in paragraphs 4.2.3, 5.2.4.2, 5.2.4.3.1, 5.2.4.3.3, 5.3.3 and .